The past decade has witnessed dramatic changes in the oil and gas industry with the advent of deep-water exploration and production. A major challenge in deep water field development is to ensure unimpeded flow of hydrocarbons to the host platform or processing facilities. Managing solids such as hydrate, waxes, asphaltene and scale is the key to the viability of developing a deep-water prospect.
The oil industry is facing a flow assurance issue with hydrate deposits in pipelines where hydrate often forms at inaccessible locations. One of the problems other than blockage is the movement of the hydrate plugs in the pipeline at high velocity, which can cause rupture in the pipeline. Any blockage in an oil/gas pipeline due to hydrate is a serious threat to the economic and cost effective strategy and also personnel safety.
The conventional way to prevent and reduce hydrate risks in transfer line and process facilities is to remove one of the elements favouring hydrate formation. For example, thermal insulation and external heating techniques are used to remove the low temperature element. Water can be removed by dehydration of the natural gas using glycol system and lowering the operating pressure can reduce the tendency for hydrate to form in the production system. However, these conventional techniques may not be feasible for some fields especially in offshore and deepwater environments due to space limitation and high insulation, heating and capital costs. Deepwater insulated pipeline costs are reported typically US$1 million per km of flowline.
Another option is to use the so-called “Thermodynamic Inhibitors”. These are water-soluble chemicals that reduce the water activity, hence shifting the hydrate phase boundary to higher pressure and/or lower temperature conditions. The common industry practice is to use methanol (MeOH) and/or mono ethylene glycol (MEG). However, due to high dosage requirement it can result in significant increase in CAPEX and OPEX, in particular at high water cut conditions, as well as logistical and environmental problems.
In recent years, the industry has focused on the application of Low Dosage Hydrate Inhibitors (LDHIs). LDHIs are classified into Kinetic Inhibitors (KIs) and Anti-Agglomerates (AAs). The KIs work by delaying nucleation and growth of crystals. However, they generally fail to inhibit the agglomeration of crystals once nucleation occurs. AAs allow gas hydrates to form but prevent the agglomeration of hydrate crystals and thus minimize the risk of pipeline plugging.
Current industry practice for hydrate prevention is injecting hydrate inhibitors at the upstream end of pipelines based on the calculated/measured hydrate phase boundary, water cut, worst pressure and temperature conditions, and the amount of inhibitor lost to non-aqueous phases. In general, systematic ways of controlling and monitoring along the pipeline and/or downstream to examine the degree of inhibition are very limited.